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This paper describes a series of experiments that used X-ray computer tomography (CT) to visualize the mobilization of remaining oil by Alkaline Surfactant (AS) and Alkaline Surfactant Polymer (ASP) flooding after conventional waterflooding. The experiments were conducted in cores drilled from Gildehauser and Bentheimer sandstone outcrop material with diameters of approximately 7.55 cm and lengths of approximately 27 cm and one meter. Crude oil with in-situ viscosities of 1.3, 2.3 and 100 cP was used in the experiments. The changes in the fluid saturation distributions with time obtained with X-ray computer tomography are subsequently used to improve the conceptual understanding of the ASP process. In addition to pressure and effluent data collected during conventional core flood experiments, phase and saturation distributions in space and time are needed to more completely interpret the results of core floods. This additional information reveals underlying mechanisms, and assists the development of models that capture the physics of ASP that can ultimately be used to provide field scale predictions for ASP performance. One important observation from the experiments is that there exist a consistent fingering pattern in the zone upstream of the oil bank. Although fingering is often considered a bad sign for a displacement process the experiments also demonstrate that the fingering zone is contained in the area upstream of the oil bank and that the velocity of the front of the oil bank is significantly greater than that of the fingering zone. The production following the clean oil bank (tail) observed in many ASP core floods is a consequence of the formation of this fingering zone. Effluent analyses conducted on the produced fluids from the long core experiments showed a sharp, rapid build up in polymer viscosity that coincides with the beginning of the tail production while the surfactant concentration only gradually increases to its injection value during the tail production. Another important observation is that a characteristic self-similar cross-sectional averaged oil saturation profile develops during ASP injection after water flood in cores containing reactive crude oil with 100 cP viscosity and in non reactive light crude oil. The implications of the self-similarity of the saturation profiles in combination with the observation that the surfactant propagation is retarded with respect to the polymer propagation results in a polymer flood ahead of the ASP-slug and a corresponding characteristic oil production profile. The characteristics of this process can be captured with an extended fractional flow approach that utilizes three fractional flow curves: one for the ASP-slug, one for polymer, and the original fractional flow curve for oil-water.

This paper describes a series of experiments that used X-ray computer tomography (CT) to visualize the mobilization of remaining oil by Alkaline Surfactant Polymer (ASP) flooding after conventional waterflooding. The experiments were conducted in cores drilled from Gildehauser and Berea sandstone outcrop material with diameters of approximately 7.55 cm and lengths of 27.5 and 99 cm. Two light crude oils with in-situ viscosities of 1.3 cP and 3.2 cP were used in the experiments. The changes in the fluid saturation distributions with time obtained with X-ray computer tomography are subsequently used to improve the conceptual understanding of the ASP process. In addition to pressure and effluent data collected during conventional core flood experiments, phase and saturation distributions in space and time are needed to more completely interpret the results of core floods. This additional information reveals underlying mechanisms, and assists the development of models that capture the physics of ASP that can ultimately be used to provide field scale predictions for ASP performance. One important observation from the experiments is that there exist a typical fingering pattern in the zone upstream of the oil bank. Although fingering is often considered a bad sign for a displacement process the experiments also demonstrate that the fingering zone is contained in the area upstream of the oil bank and that the velocity of the front of the oil bank is significantly greater than that of the fingering zone. The tail production observed in many ASP core floods is a consequence of the formation of this fingering zone. Effluent analyses conducted on the produced fluids from the long core experiments showed an instantaneous build up in polymer viscosity that coincides with the beginning of the tail production while the surfactant concentration only gradually increases to its injection value during the tail production. Another important observation is that a characteristic self-similar cross-sectional averaged oil saturation profile develops during ASP injection after water flood in cores containing non reactive light crude oil. The implications of the self-similarity of the saturation profiles in combination with the observation that the surfactant propagation is retarded with respect to the polymer propagation results in a polymer flood ahead of the ASP-slug and a corresponding characteristic oil production profile. The characteristics of this process can be captured with an extended fractional flow approach that utilizes three fractional flow curves: one for the ASP-slug, one for polymer, and the original fractional flow curve for oil-water.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractTraditionally bullhead water control consists of the placement of water-soluble chemicals without mechanically isolating oil layers. In order to be successful, bullhead treatments should block water-bearing layers without affecting the permeability of the oil-bearing layers too much. This paper reports an experimental investigation of an innovative water shutoff chemical deemed suitable to accomplish this task. The chemical is soluble in oil without any reaction, and is transferred into and reacts with water to form a stable gel. Core flow experiments consisting mostly of the injection of either oil or water in cores containing the chemical dissolved in oil were performed to investigate the ability of the gel to reduce water permeability while maintaining oil permeability. To ensure that the results are relevant for designing field applications, the experiments were performed under conditions encountered in various sandstone reservoirs in the North Sea, Croatia and other regions. Permeabilities and temperature ranging from 100 to 300 mD and 70-90 0 C were therefore considered in this study. The influence of the other physical parameters, such as viscosity, concentration of active chemical in oil chemical, injection rate, etc., was also investigated.

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractTraditionally bullhead water control consists of the placement of water-soluble chemicals without mechanically isolating oil layers. In order to be successful, bullhead treatments should block water-bearing layers without affecting the permeability of the oil-bearing layers too much. This paper reports an experimental investigation of an innovative water shutoff chemical deemed suitable to accomplish this task. The chemical is soluble in oil without any reaction, and is transferred into and reacts with water to form a stable gel. Core flow experiments consisting mostly of the injection of either oil or water in cores containing the chemical dissolved in oil were performed to investigate the ability of the gel to reduce water permeability while maintaining oil permeability. To ensure that the results are relevant for designing field applications, the experiments were performed under conditions encountered in various sandstone reservoirs in the North Sea, Croatia and other regions. Permeabilities and temperature ranging from 100 to 300 mD and 70-90 0 C were therefore considered in this study. The influence of the other physical parameters, such as viscosity, concentration of active chemical in oil chemical, injection rate, etc., was also investigated.

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